Without limiting the scope of the present invention, its background will be described in relation to setting packers, as an example.
In the course of treating and preparing a subterranean well for production, well packers are commonly run into the well on a conveyance such as a work string or production tubing. The purpose of the packer is to support production tubing and other completion equipment, such as sand control assemblies adjacent to a producing formation, and to seal the annulus between the outside of the production tubing and the inside of the well casing to block movement of fluids through the annulus past the packer location.
Production packers and other types of downhole tools may be run down on production tubing to a desired depth in the wellbore before they are set. Certain conventional production packers are set hydraulically, requiring that a pressure differential be created across a setting piston. Typically, this is accomplished by running a tubing plug on wireline, slick line, electric line, coiled tubing or another conveyance means through the production tubing down into the downhole tool. Then the fluid pressure within the production tubing is increased, thereby creating a pressure differential between the fluid within the production tubing and the fluid within the wellbore annulus. This pressure differential actuates the setting piston to expand the production packer into sealing engagement with the production liner or casing. Before resuming normal operations through the production tubing, the tubing plug must be removed, typically by retrieving the plug back to the surface of the well.
As operators increasingly pursue production completions in deeper water offshore wells, highly deviated wells and extended reach wells, the rig time required to set a tubing plug and thereafter retrieve the plug can negatively impact the economics of the project, as well as add unacceptable complications and risks. To address the issues associated with hydraulically-set downhole tools, an interventionless setting technique was developed. In particular, a hydrostatically-actuated setting module was designed to be incorporated into the bottom end of a downhole tool, and this module exerts an upward setting force on the downhole tool. The hydrostatic setting module may be actuated by applying pressure to the production tubing and the wellbore at the surface, with the setting force being generated by a combination of the applied surface pressure and the hydrostatic pressure associated with the fluid column in the wellbore. In particular, a piston of the hydrostatic setting module is exposed on one side to a vacuum evacuated initiation chamber that is initially closed off to wellbore annulus fluid by a port isolation device, and the piston is exposed on the other side to an enclosed evacuated chamber generated by pulling a vacuum.
In operation, once the downhole tool is positioned at the required setting depth, surface pressure is applied to the production tubing and the wellbore annulus until the port isolation device actuates, thereby allowing wellbore fluid to enter the initiation chamber on the one side of the piston while the chamber engaging the other side of the piston remains at the evacuated pressure. This creates a differential pressure across the piston that causes the piston to move, beginning the setting process. Once the setting process begins, O-rings in the initiation chamber move off seat to open a larger flow area, and the fluid entering the initiation chamber continues actuating the piston to complete the setting process. Therefore, the bottom-up hydrostatic setting module provides an interventionless method for setting downhole tools since the setting force is provided by available hydrostatic pressure and applied surface pressure without plugs or other well intervention devices.
However, the bottom-up hydrostatic setting module may not be ideal for applications where the wellbore annulus and production tubing cannot be pressured up simultaneously. Such applications include, for example, when a packer is used to provide liner top isolation or when a packer is landed inside an adjacent packer in a stacked packer completion. The production tubing cannot be pressured up in either of these applications because the tubing extends as one continuous conduit out to the pay zone where no pressure, or limited pressure, can be applied.
In such circumstances, if a bottom-up hydrostatic setting module is used to set a packer above another sealing device, such as a liner hanger or another packer, for example, there is only a limited annular area between the unset packer and the set sealing device below. Therefore, when the operator pressures up on the wellbore annulus, the hydrostatic pressure begins actuating the bottom-up hydrostatic setting module to exert an upward setting force on the packer. However, when the packer sealing elements start to engage the casing, the limited annular area between the packer and the lower sealing device becomes closed off and can no longer communicate with the upper annular area that is being pressurized from the surface. Thus, the trapped pressure in the limited annular area between the packer and the lower sealing device is soon dissipated and may or may not fully set the packer.
Therefore, a need has arisen for a packer that is operable to be set without tripping a plug into the wellbore. A need has also arisen for a packer that is operable to be set without the application of tubing pressure from the surface. Further, a need has arisen for a packer that is operable to be set without the application of annular pressure from the surface.